It is desirable for companies that drill oil and gas wells to obtain quantitative information about formations that contain hydrocarbons. This information may be useful in order to determine the amount of oil and gas in the reservoir, how much of it can be recovered, the rate of production, and ultimately whether the hydrocarbons can be developed and produced for financial gain. Quantitative rock property data can come from various measures including indirect and direct means of evaluation. Because of the different methodologies practiced through the industry to obtain quantitative rock properties, data that is generated inherently contains variables of unknown significance because multiple samples and measurement scales are used to produce the data set. The data set may include rock properties such as porosity, absolute permeability, relative permeability, and capillary pressure data, but is not limited to such properties.
Conventional indirect means for estimating rock properties exist in the art. Among other types of indirect means, almost all wells use electric logs, run in either the open hole after drilling or the casing lined well to measure certain attributes of hydrocarbon bearing formations. Several types of open hole logs may be used to measure the properties required for an effective determination. For example, a “triple combo” log measures bulk density, neutron porosity, and formation resistivity. Using known methods, those attributes may be used with mathematical correlations to derive useful parameters such as reservoir effective porosity, effective permeability, water saturation, and other properties. Additional mathematical equations may be applied to triple combo log data to estimate rock mechanical properties, such as Young's modulus, Poisson's ratio, and in-situ stress. These parameters, especially permeability and the rock mechanical properties, play a crucial role in making decisions about reservoir size, quality, and producibility.
However, there are typically limitations to measuring the properties in this manner. Each of the logging tools incorporates one or more sensors to measure a desired attribute and sometimes different logging tools are run simultaneously to reduce the time required for the surveys. Logging techniques do not require physical examination or direct inspection of the rock for the most part. For example, certain logging tools obtain images of the formation to measure a desired attribute of that formation. Another typical limitation is that the precise location of the measurement is only known relative to the estimated position of the logging tool at the time the measurement is made and the measurements taken are average values over some thickness of formation which can range from inches to feet. A rock property such as Formation Factor is used to determine water saturation from resistivity log measurements. In order to make those calculations, a resistivity measurement is obtained from the log in a region that is thought to contain 100% water and compared to other locations in the rock that appear to contain some amount of hydrocarbon in addition to connate water.
Direct methods are also available for measuring rock properties. A conventional direct method typically involves obtaining specimens of the rock to be evaluated and performing laboratory experiments on those specimens. One example of such an experiment is coring, a process by which intact rock specimens can be obtained from an oil and gas well. For example, a “whole core” is obtained by using a special drill bit that cuts a cylinder of rock over the interval of interest. The total cylinder can be on the order of four inches in diameter and hundreds of feet long. For handling purposes, the core may be cut into three foot lengths. From those lengths, short plugs of 1″ to 1½″ diameter are then taken for the laboratory tests. Because different laboratory tests require different sizes, shapes, and orientation of the samples relative to the original rock, several samples are typically prepared from a region of the core that appears to be similar. For example, it is useful to know both the horizontal and vertical permeabilities of a reservoir rock. To obtain these properties in the physical lab, one reservoir rock sample must be cut perpendicular to the core's axis whereas another reservoir rock sample must be cut parallel to the core's axis. Laboratory tests are then performed on the samples to yield the permeability in one direction based on the cut. However, there is no assurance that the obtained reservoir rock samples contain identical rock properties even though the samples came from the same region of the core and are visibly similar. Thus, physical laboratory analysis involved with direct methods of measuring rock properties is limited because of the scale, size, and requirement of different samples for different pieces of equipment. The results obtained from such an analysis are usually not internally consistent because the sample specimens may vary in their respective properties.
Once the sample specimen has been used to determine a property such as, for example, a horizontal or vertical permeability, that sample may not be useful for obtaining other rock properties. For example, to determine grain size distribution, yet another specimen must be obtained from the same region of the core and crushed so that a laser particle size analysis or sieve analysis can be conducted.
Similarly, as in the aforesaid example, other Special Core Analyses (SCAL) would also require their own dedicated samples that are sometimes altered or destroyed in the procedure. For example, relative permeability studies are conducted using steady state or unsteady state methods which require a flow rate to be selected for the lab test. If there is a need to determine relative permeability at a different flow rate or to change from an unsteady state to a steady state analysis, the core used for the initial analysis cannot be relied upon to be in original condition, if it is available at all. Thus, a new core sample must be used.
Similarly, capillary pressure determinations in the lab require pumping fluid into a core while monitoring pressure and flow rate. However, as in the aforementioned examples, once complete, the same core sample would not be useful for another study at a different set of flow rates and pressures.
Accordingly, it is an objective of the present invention to provide a method for obtaining a consistent and integrated set of parameters from a sample porous media. It is a further object of the invention to provide such a methodology for obtaining rock properties from a porous media from a sample such that the sample remains intact throughout the process. In particular, sample specimens of porous media can vary considerably, and there is no guarantee that the chosen rock specimens or locations all have the identical rock properties even though they came from the same region of the core and were visibly similar. Yet, the resulting data will be used as if all the samples were identical in every way. It is a further object of the invention to provide a methodology to obtain parameters for reservoir modeling from a single sample specimen by obtaining a plurality of physical properties of the single sample specimen, such that the sample specimen remains intact throughout the process.
Other information besides rock properties is needed to fully characterize oil and gas reservoirs for evaluation and predictive purposes. There are various techniques to collect reservoir fluid samples, pressure data, and information about the volumetric extent of the reservoir. Coupled with rock property data obtained from logs and cores, calculations can be made to determine where to drill wells, how to complete them, how efficiently wells are producing, and when they are depleted. Modern petroleum engineering methods use computer simulations to analyze the large volume of data that is required to do a thorough and presumably accurate analysis. The quality of the input data is critical to achieving a result that has a high probability of being correct. It is another object of the present invention to reduce the range of uncertainty of the input data from a sample porous media to improve the accuracy of the resultant output.
There is a need, therefore, for a methodology and system for providing consistent and integrated rock properties from a porous media with high accuracy to result in improved predictability of oil, gas, or reservoir well design and fluid flow characteristics. There is a further need for obtaining rock properties from a porous media such that the sample specimen may remain intact. There is a further need for performing laboratory analysis on a sample specimen that can come to stabilization sooner in the simulator and require less history matching overall.
As presently stated, these and other limitations within the current art are solved by the present invention.